The front-month price of natural gas at Louisiana’s Henry Hub–the official delivery point for the volumes underpinning the futures contracts traded on the New York Mercantile Exchange–has surged to more than $6.00 per million British thermal units (mmBtu) this winter.
And natural-gas prices in parts of the Northeast that were hardest hit by the cold have surged even higher. Check out this graph tracking spot natural-gas prices at the Algonquin Citygate hub serving Boston.
However, investors shouldn’t confuse this seasonal rally with a durable recovery in natural-gas prices. All this recent upside stems from weather-related phenomena, not newfound discipline on the supply side or sustainable demand growth.
As my colleague Elliott Gue discussed in It’s Cold Outside: Buy the Dips, the big chill that gripped the nation in January disrupted all manner of economic activity.
Snowstorms and plummeting temperatures combined to send the Institute for Supply Management’s Purchasing Managers Index for the US manufacturing sector plummeting to 51.3 in January from 56.5 in December 2013.
To ward off the cold, households and businesses have fired up their heaters; robust demand for thermal fuel has reduced the volume of working natural gas in storage to about 750 billion cubic feet less than the five-year average for this time of year.
Source: Energy Information Administration, Energy & Income Advisor
Meanwhile, frigid temperatures have led to wellhead freeze-offs, problems at natural-gas processing plants and general operating difficulties in some of the nation’s most prolific shale oil and gas plays.
The challenges caused by the cold weather show up in LCI Insights’ estimates of weekly US natural-gas production; output dipped at the end of December and didn’t recover fully until temperatures moderated toward the end of February.
But the tightest natural-gas market in more than a decade won’t last.
Recall the no-show winter of 2011-12, when natural-gas prices plummeted to less than $2.00 per mmBtu because of weak heating demand.
In that instance, ultra-depressed fuel prices spurred coal-to-gas switching among electric utilities with the flexibility to burn either thermal fuel; coupled with a normal winter in 2012-13, this incremental consumption eventually returned the market to equilibrium.
And as natural-gas prices recovered from ultra-depressed to depressed levels, utilities reverted to burning coal to take advantage of superior economics. This gas-to-coal switching explains why US utilities’ consumption of natural gas tumbled to 22 billion cubic feet per day in 2013 from 26 billion cubic feet per day in 2012.
Meanwhile, innovative new technologies such as pad drilling and evolving well designs and completion techniques have lowered production costs and boosted initial flow rates in the Marcellus Shale and other prominent plays. (See Salute Your Drillmasters: Efficiency Gains Lower Production Costs.)
The start-up of new midstream capacity–gathering lines, processing facilities and pipelines–in the prolific Marcellus Shale (about 18 percent of US natural-gas production last year) and the emerging Utica Shale should help to refill storage capacity before the 2014-15 winter.
The futures market reinforces that the recent upsurge in natural-gas prices, though impressive, won’t have staying power.
The blue line on this graph tracks US natural-gas futures prices one year ago, while the orange line tracks represents the current futures curve.
Although the price of natural gas for delivery over the next 12 months has increased from year-ago levels, futures prices beyond March 2015 have declined.
In other words, market participants expect the weather-induced strength in US natural-gas prices to fade over the summer and prices to return to the neighborhood of $4.00 per mmBtu by early 2015.
This retrenchment might occur even faster, as the current price environment could tempt long-suffering gas producers to accelerate their drilling and completion activity this summer.
Elliott and Roger on Jun. 30, 2021
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